|Publication number||US20090283279 A1|
|Application number||US 12/469,521|
|Publication date||Nov 19, 2009|
|Filing date||May 20, 2009|
|Priority date||Apr 25, 2005|
|Publication number||12469521, 469521, US 2009/0283279 A1, US 2009/283279 A1, US 20090283279 A1, US 20090283279A1, US 2009283279 A1, US 2009283279A1, US-A1-20090283279, US-A1-2009283279, US2009/0283279A1, US2009/283279A1, US20090283279 A1, US20090283279A1, US2009283279 A1, US2009283279A1|
|Inventors||Dinesh R. Patel, Philippe Gambier, Jose F. Garcia|
|Original Assignee||Schlumberger Technology Corporation|
|Export Citation||BiBTeX, EndNote, RefMan|
|Referenced by (24), Classifications (12)|
|External Links: USPTO, USPTO Assignment, Espacenet|
This application claims the benefit under 35 U.S.C. § 119(e) of and is a continuation-in-part of U.S. Provisional Application Ser. No. 60/594,628, entitled “Zonal Isolation Tool,” filed Apr. 25, 2005; and of U.S. application Ser. No. 11/308,617, entitled, “Zonal Isolation Tools and Methods of Use,” filed Apr. 12, 2006, both hereby incorporated by reference.
A zonal isolation tool should provide reliable, long-term isolation between two or more subsurface zones in a well. A typical application would be to segregate two zones in an open-hole region of a well, the zones being separated by a layer of low permeability shale in which the zonal isolation tool is placed. A nominal size configuration would be usable in wellbores drilled with an 8½ inch (21.6 cm) outer diameter bit below 9⅝ inch (24.5 cm) casing, but the use of zonal isolation tools is not limited to any particular size, or to use in open holes. By segregating open-hole intervals, downhole chokes may be used for production management. Similarly, selective zonal injection may be performed. If distributed temperature sensing is placed in the well, monitoring predictive control is possible.
A conventional completion assembly 10 with a zonal isolation tool 12 is illustrated in
However, most of the current openhole zonal isolation systems are not designed to enable long term, openhole, hydraulic isolation. Specific challenges include sealing and anchoring the system, and the ability to allow for expansion and/or contraction due to thermal effects, all located within the openhole interval of a sandface completion. There are also issues of coping with retaining the differential pressure rating for wider open hole internal diameters or changes in the open hole internal diameter within the specified operating envelope.
Therefore, while there have been some improvements in zonal isolation tool designs and systems, further improvement is desired.
In general, a zonal isolation system for use in a well is provided. The zonal isolation system includes a zonal isolation tool, at least one anchor, and at least one polished bore receptacle. The zonal isolation system includes a setting string for activation of the zonal isolation tool and/or the at least one anchor. The zonal isolation system may also include an isolation string for maintaining separation zones during production or injection of the well.
It is to be noted, however, that the appended drawings are not to scale and illustrate only some embodiments of this invention, and are therefore not to be considered limiting of its scope.
In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those skilled in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.
Described herein is a zonal isolation system 80 for use in wellbores. A “wellbore” may be any type of well, including, but not limited to, a producing well, a non-producing well, an experimental well, and exploratory well, and the like. Wellbores may be vertical, horizontal, any angle between vertical and horizontal, diverted or non-diverted, and combinations thereof, for example a vertical well with a non-vertical component. Also, in the description, the terms “connect”, “connection”, “connected”, “in connection with”, and “connecting” are used to mean “in direct connection with” or “in connection with via another element”. The term “set” is used to mean “one element” or “more than one element”. The terms “up” and “down”, “upper” and “lower”, “upwardly” and “downwardly”, “upstream” and “downstream”, “above” and “below”, and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly described some embodiments as disclosed herein. However, when applied to equipment and methods for use in wells that are deviated or horizontal, such terms may refer to a left to right, right to left, or other relationship as appropriate.
Referring now to
Referring now to
The zonal isolation tool 29 of this embodiment uses hydroforming pressure as a first step to energize. Initial inflation will affect a long length of sealing contact, assuring good compliance to the open hole. After initial inflation, a compressive load is applied via linear piston 7 (
The following are operational considerations, occurring sequentially: (1) the tubing or base pipe 15 must be open to the sealing member; (2) the initial inflation must stop when a defined pressure within sealing member 34 is reached; (3) inflation port 21 must be assuredly blanked from tubing or base pipe 15; and (4) a vent must open between sealing member 34 and annulus 6. As illustrated in
As illustrated in
A setting pressure of approximately 1,500 psi (about 10.3 megaPascals) is used to lengthen the contact length of seal 34 with the formation (
A venting port 60 (
Carriage 36 is illustrated in
Inner sealing element 50 (
Outer sealing element 52 may be a rubber cylinder bonded to the ends of the carriage 36 to provide sealing against the formation. Outer sealing element 52 may have any thickness that provides appropriate tear and wear resistance during conveyance and good conformability to open-hole irregularities. Its thickness may range from about 0.30 to about 0.70 inch (from about 0.76 to about 1.78 cm) to. Outer seal element 52 may also comprise 80 durometer HNBR, and may comprise other materials as discussed herein.
Dashed circle “A” in
Anti-extrusion sheets 54 (
The outer elastomeric elements engage an adjacent surface of a well bore, casing, pipe, tubing, and the like. Other elastomeric layers between the inner and outer elastomeric members may be provided for additional flexibility and backup. A non-limiting example of an elastomeric element is rubber, but any elastomeric materials may be used. A separate membrane may be used with an elastomeric element if further wear and puncture resistance is desired. A separate membrane may be interleaved between elastomeric elements if the elastomeric material is insufficient for use alone. The elastomeric material of outer sealing elements should be of sufficient durometer for expandable contact with a well bore, casing, pipe or similar surface. In some embodiments the elastomeric material may be of sufficient elasticity to recover to a diameter smaller than that of the wellbore to facilitate removal therefrom. The elastomeric material should facilitate sealing of the well bore, casing, or pipe in the inflated state.
“Elastomer” as used herein is a generic term for substances emulating natural rubber in that they stretch under tension, have a high tensile strength, retract rapidly, and substantially recover their original dimensions (or even smaller in some embodiments). The term includes natural and man-made elastomers, and the elastomer may be a thermoplastic elastomer or a non-thermoplastic elastomer. The term includes blends (physical mixtures) of elastomers, as well as copolymers, terpolymers, and multi-polymers. Examples include ethylene-propylene-diene polymer (EPDM), various nitrile rubbers which are copolymers of butadiene and acrylonitrile such as Buna-N (also known as standard nitrile and NBR). By varying the acrylonitrile content, elastomers with improved oil/fuel swell or with improved low-temperature performance can be achieved. Specialty versions of carboxylated high-acrylonitrile butadiene copolymers (XNBR) provide improved abrasion resistance, and hydrogenated versions of these copolymers (HNBR) provide improve chemical and ozone resistance elastomers. Carboxylated HNBR is also known. Other useful rubbers include polyvinylchloride-nitrile butadiene (PVC-NBR) blends, chlorinated polyethylene (CM), chlorinated sulfonate polyethylene (CSM), aliphatic polyesters with chlorinated side chains such as epichlorohydrin homopolymer (CO), epichlorohydrin copolymer (ECO), and epichlorohydrin terpolymer (GECO), polyacrylate rubbers such as ethylene-acrylate copolymer (ACM), ethylene-acrylate terpolymers (AEM), EPR, elastomers of ethylene and propylene, sometimes with a third monomer, such as ethylene-propylene copolymer (EPM), ethylene vinyl acetate copolymers (EVM), fluorocarbon polymers (FKM), copolymers of poly(vinylidene fluoride) and hexafluoropropylene (VF2/HFP), terpolymers of poly(vinylidene fluoride), hexafluoropropylene, and tetrafluoroethylene (VF2/HFP/TFE), terpolymers of poly(vinylidene fluoride), polyvinyl methyl ether and tetrafluoroethylene (VF2/PVME/TFE), terpolymers of poly(vinylidene fluoride), hexafluoropropylene, and tetrafluoroethylene (VF2/HPF/TFE), terpolymers of poly(vinylidene fluoride), tetrafluoroethylene, and propylene (VF2/TFE/P), perfluoroelastomers such as tetrafluoroethylene perfluoroelastomers (FFKM), highly fluorinated elastomers (FEPM), butadiene rubber (BR), polychloroprene rubber (CR), polyisoprene rubber (IR), IM, polynorbornenes, polysulfide rubbers (OT and EOT), polyurethanes (AU) and (EU), silicone rubbers (MQ), vinyl silicone rubbers (VMQ), fluoromethyl silicone rubber (FMQ), fluorovinyl silicone rubbers (FVMQ), phenylmethyl silicone rubbers (PMQ), styrene-butadiene rubbers (SBR), copolymers of isobutylene and isoprene known as butyl rubbers (IIR), brominated copolymers of isobutylene and isoprene (BIIR) and chlorinated copolymers of isobutylene and isoprene (CIIR).
The expandable portions of the packers may include continuous strands of polymeric fibers cured within the matrix of the integral composite body comprising elastomeric elements. Strands of polymeric fibers may be bundled along a longitudinal axis of the expandable packer body parallel to longitudinal cuts in a laminar interior portion of the expandable body. This can facilitate expansion of the expandable portion of the composite body yet provide sufficient strength to prevent catastrophic failure of the expandable packer upon complete expansion.
The expandable portions of the tools may also contain a plurality of overlapping reinforcement members. These members may be constructed from any suitable material, for example high strength alloys, fiber-reinforced polymers and/or elastomers, nanofiber, nanoparticle, and nanotube reinforced polymers and/or elastomers, or the like, all in a manner known and disclosed in U.S. patent application Ser. No. 11/093390, filed on Mar. 30, 2005, entitled “Improved Inflatable Packers”, the entirety of which is incorporated by reference herein.
The zonal isolation tools may be constructed of a composite or a plurality of composites so as to provide flexibility. The expandable portions of the tools may be constructed out of an appropriate composite matrix material, with other portions constructed of a composite sufficient for use in a wellbore, but not necessarily requiring flexibility. The composite may be formed and laid by conventional means known in the art of composite fabrication. The composite may be constructed of a matrix or binder that surrounds a cluster of polymeric fibers. The matrix can comprise a thermosetting plastic polymer which hardens after fabrication resulting from heat. Other matrices are ceramic, carbon, and metals, but the invention is not so limited. The matrix can be made from materials with a very low flexural modulus close to rubber or higher, as required for well conditions. The composite body may have a much lower stiffness than that of a metallic body, yet provide strength and wear impervious to corrosive or damaging well conditions. The composite tool body may be designed to be changeable with respect to the type of composite, dimensions, number of cable and fibrous layers, and shapes for differing downhole environments.
It is understood that the zonal isolation tool may be any type of isolation or separation device suitable for use in an openhole environment. These include, but are not limited to, hydroform-compress-energize packer, swellable elastomer packer, inflatable ECP, or rubber-compression packer. Furthermore, it is understood that multiple zonal isolation tools may be positioned or oriented in any manner to generate uni-directional or bi-directional sealing.
Referring now to the zonal isolation system illustrated in
To enable setting of the zonal isolation tool 29 discussed above, the upper polished bore receptacle 86 may be placed above the zonal isolation tool and a lower polished bore receptacle 88 may be placed below the zonal isolation tool, as shown in
The zonal isolation system 80 may also include a pair of anchors for preventing movement of the zonal isolation tool 29 relative to the openhole by gripping the borehole wall, as shown in
The first anchor 82 and the second anchor 84 support tensile and compressive forces on the tubular string, and provide a torsional load path. The effectiveness of the anchors may be a function of the friction coefficient of the openhole and the radial load applied against the formation. The coefficient of friction is related to the type of formation and fluids present downhole in the region of setting the zonal isolation system. In order to protect the formation from fracture, it is important that the radial loads remain below the fracture pressure of the formation. Therefore, the load should be distributed over a large surface area.
The anchors used with the zonal isolation system may be of several types. For example, as illustrated in
A two-stage slip anchor 122 may also be used and contains a pair of support slips on the extremities, or ends of the anchor, and a pair of principal slips in a center of the anchor, as shown in
In the alternative, a self-locking anchor 124 may be used, as illustrated in
It is understood that a penetrator-type anchor system 126 shown in
The tubulars attached to the zonal isolation system may expand and contract due to thermal changes. The expansion joint 90 allows for contraction and expansion of that tubular basepipe. The expansion joint 90 is capable of supporting the weight of the tubular string by allowing for changes in length but still maintaining pressure integrity from its inner diameter to its outer diameter. The expansion joint may be inactive (locked) during installation and then activated (unlocked) during the setting and operation stages.
The setting string 92 may set all of the components in a single trip simultaneously or one device at a time. The setting string 92 has several features to assist in the setting of the described components. The collet 118 may be attached to the setting string 92 which mates with the polished bore receptacle which includes the locating profile 112 discussed above. The setting string 92 may also comprise ports, checks, or valves to facilitate wash-down or debris removal capabilities while running in the borehole (not shown). These features assist operators specifically in long, horizontal, openhole completions. It is understood that the setting string may also comprise devices to set other completion equipment during the same single trip, such as production packers, sump packers, and formation isolation valves.
The isolation string 94 maintains pressure integrity along its length, and provides the remaining separation for zonal isolation. The isolation string may be installed in place of the setting string after all of the components have been activated and are operational. The isolation string 94 may include a packing stack to seal in the lower polished bore receptacle which is located downhole, and may also include a locating collet to mate with the locating profile 112 on the lower polished bore receptacle.
It is understood that the zonal isolation tools as described and claimed herein may connect in any number of ways to their wellbore counterparts. Each end of the zonal isolation system may be adapted to be attached in a tubular string. This can be through threaded connections, friction fits, expandable sealing means, and the like, all in a manner well known in the oil tool arts. Although the term tubular string is used, this can include jointed or coiled tubing, casing or any other equivalent structure for positioning tools as disclosed herein. The materials used can be suitable for use with production fluid or with an inflation fluid.
The embodiments described herein may be used in an open hole for sandface completions utilizing stand-alone screens. However, the embodiments described herein may also be adapted for use in open-hole gravel pack sand control applications. In the latter role, the embodiments described herein may incorporate the use of alternate path transport and shunt tubes to assist gravel slurry placement. Additionally, the embodiments described herein may be used in sand control applications utilizing expandable screens. Aside from the various sand control applications listed, the embodiments described herein may also be used as an annular barrier, or for compartmentalizing long open-hole sections.
Although only a few exemplary embodiments of this invention have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the exemplary embodiments without materially departing from the spirit of this invention. Accordingly, all such modifications are intended to be included within the scope of this invention as defined in the following claims.
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|U.S. Classification||166/382, 166/118|
|International Classification||E21B23/01, E21B33/12, E21B23/00|
|Cooperative Classification||E21B23/06, E21B33/1216, E21B33/129, E21B33/1272|
|European Classification||E21B23/06, E21B33/127B, E21B33/129|